Image analysis of core materials in the geological sciences has been primarily the discipline of the sedimentologists and the petrographers. Two dimensional (2D) image data from optical and scanning electron microscopy (SEM) techniques have been utilized to estimate porosity, pore size, grain size, flow units, permeability, velocity and compressibility. Conventional petrographic techniques allow the identification of mineral phase information and origins of mineral phases (e.g., detrital or authigenic). Length scales down to nanometers can be probed.
On the other hand, X-ray micro computed tomography (CT), with its ability to generate detailed three dimensional (3D) images of pore structure on the micron scale, has recently become accepted as a useful complement to the well established 2D microscopic techniques. The availability of high quality “turn-key” tomographic systems has recently facilitated the rapid increase in the use of these systems. These systems allow one to obtain pore/grain scale information on porous materials in three dimensions. Unfortunately, the conventional micro-CT imaging gives poor mineral discrimination and is limited to spatial resolutions of about 1 micron.
Increasing levels of attention have recently been focussed on the characterization and measurement of properties at the pore/grain/clay scale of core materials; understanding properties at this scale is crucial to applications in the oil and gas industries. Analyses of core samples are used to generate key petrophysical and multiphase flow properties. These properties are crucial to reducing the high financial risk that petroleum companies face in finding, bringing to production and operating oil and gas fields. Compared to the cost of bringing a new field into production or the potential profit from extending the life of an existing field, the cost of the analyses themselves is low. Core analysis remains the industry standard data for estimating reserves and predicting recovery rates. This is despite the fact that core analysis may often provide conflicting data and data which is difficult to interpret and difficult to reproduce. Such difficulties are at least partially due to the complex interfacial phenomena that need to be addressed at a fundamental level for better understanding of multiphase flow properties.
Measurements obtained in conventional multiphase flow experiments within core laboratories are used to study both the pore scale structure of the rock and the interfacial properties of the fluid/fluid and fluid/rock interactions. There is an enormous interest in the development of rules and methods for modelling pore level displacements that apply to multiphase flow. Pore network models which include rules for occupancy of fluids in individual pores under different wettability scenarios (water wet, mixed wet large/small) are being developed in an attempt to improve understanding of multiphase flow properties in real porous materials (see e.g, Morrow & Mason, “Recovery of Oil by spontaneous imbibition”, Current Opinion in Colloid & Interface Science, Vol. 6, pp. 321-337 (2001) and H. Behbahani and M. Blunt, “Analysis of Imbibition in mixed wet rocks using pore scale modelling”, SPE 90132, presented at SPE Annual Technical Conference, Houston, 2004). To date, no methodology has allowed the direct calibration of the pore network model descriptions of the different fluid phases to experimental pore level information on the distribution of the fluid phases under realistic wettability conditions. Therefore, no direct pore-level calibration of pore scale modelling has been possible.
It has been demonstrated that direct simulation on CT images can be used to predict single phase properties of porous materials; e.g. permeability, conductivity and mercury injection capillary pressure curves (see e.g. “Digital core laboratory: Petrophysical analysis from 3D imaging of reservoir core fragments”, C. H. Arms, F. Bauget, A. Ghous, A. Sakellariou, T. J. Senden, A. P. Sheppard, R. M. Sok, W. V. Pinczewski, J. Kelly, and M. A. Knackstedt, Petrophysics, 46(4), 260-277, 2005.)
Previous studies have demonstrated the ability to identify the pore scale distribution of fluids in 3D on the basis of micro-CT imaging experiments (see Seright et al., “Characterizing disproportionate permeability reduction using synchrotron X-ray computed tomography”, SPE Reservoir Evaluation and Engineering, October 2002, pp. 355-364). However these studies were severely hampered by the need to flood the core sample under investigation, without removing the sample from the X-ray CT beam line. This limits experiments undertaken at the pore scale in 3D to simple flooding experiments.
Moreover, these experiments have been limited by the need to maintain micron-perfect positioning of the core material over long acquisition times. Thus, an experiment involving significant equilibration times (e.g. steady state relative permeability measurements under reservoir conditions, ageing of a core in native crude and brine, porous plate flooding etc.) may require the sample to remain on the CT equipment for weeks or even months.